1. Field of the Invention
The present invention relates to improved subterranean drill bits and abrasive cutter elements for application with such bits. More specifically, the present invention is directed to a stabilized drill bit including an improved cutting element incorporating enhanced wear characteristics.
2. Description of the Prior Art
Diamond cutters have traditionally been employed as the cutting or wear portion of drilling and boring tools. Known applications for such cutters include the mining, construction, oil and gas exploration and oil and gas production industries. An important category of tools employing diamond cutters are those drill bits of the type used to drill oil and gas wells.
The drilling industry classifies commercially available drill bits as either roller bits or diamond bits. Roller bits are those which employ steel teeth or tungsten carbide inserts. As the name implies, diamond bits utilize either natural or synthetic diamonds on their cutting surfaces. A "fixed cutter", as that term is used both herein and in the oil and gas industries, describes drill bits that do not employ a cutting structure with moving parts, e.g. a rolling cone bit.
The International Association of Drilling Contractors (IADC) Drill Bit Subcommittee has officially adopted standardized fixed terminology for the various categories of cutters. The fixed cutter categories identified by IADC include polycrystalline diamond compact (pdc), thermally stable polycrystalline(tsp), natural diamond and an "other" category. Fixed cutter bits falling into the IADC "other" category do not employ a diamond material as any kind as a cutter. Commonly, the material substituted for diamond includes tungsten carbide. Throughout the following discussion, references made to "diamond" include pdc, tsp, natural diamond and other cutter materials such as tungsten carbide.
An oil field diamond bit typically includes a shank portion with a threaded connection for mating with a drilling motor or a drill string. This shank portion can include a pair of wrench flats, commonly referred to a "breaker slots", used to apply the appropriate torque to properly make-up the threaded shank. In a typical application, the distal end of the drill bit is radially enlarged to form a drilling head. The face of the drilling head is generally round, but may also define a convex spherical surface, a planar surface, a spherical concave segment or a conical surface. In any of the applications, the body includes a central bore open to the interior of the drill string. This central bore communicates with several fluid openings used to circulate fluids to the bit face. In contemporary embodiments, nozzles situated in each fluid opening control the flow of drilling fluid to the drill bit.
The drilling head is typically made from a steel or a cast "matrix" provided with polycrystalline diamond cutters. Prior art steel bodied bits are machined from steel and typically have cutters that are press-fit or brazed into pockets provided in the bit face. Steel head bits are conventionally manufactured by machining steel to a desired geometry from a steel bar, casting, or forging. The cutter pockets and nozzle bores in the steel head are obtained through a series of standard turning and milling operations. Cutters are typically mounted on the bit by brazing them directly into a pocket. Alternatively, the cutters are brazed to a mounting system and pressed into a stud hole, or, still alternatively, brazed into a mating pocket.
Matrix head bits are conventionally manufactured by casting the matrix material in a mold around a steel core. This mold is configured to give a bit of the desired shape and is typically fabricated from graphite by machining a negative of the desired bit profile. Cutter pockets are then milled into the interior of the mold to proper contours and dressed to define the position and angle of the cutters. The internal fluid passageways in the bit are formed by positioning a temporary displacement material within the interior of the mold which is subsequently removed. A steel core is then inserted into the interior of the mold to act as a ductile center to which the matrix materials adhere during the cooling stage. The tungsten carbide powders, binders and flux are then added to the mold around the steel core. Such matrices can, for example, be formed of a copper-nickel alloy containing powdered tungsten carbide. Matrices of this type are commercially available to the drilling industry from, for example, Kennametal, Inc.
After firing the mold assembly in a furnace, the bit is removed from the mold after which time the cutters are mounted on the bit face in the preformed pockets. The cutters are typically formed from polycrystalline diamond compact (pdc) or thermally stable polycrystalline (tsp) diamond. PDC cutters are brazed within an opening provided in the matrix backing while tsp cutters are cast within pockets provided in the matrix backing.
Cutters used in the above categories of drill bits are available from several commercial sources and are generally formed by sintering a polycrystalline diamond layer to a tungsten carbide substrate. Such cutters are commercially available to the drilling industry from General Electric Company under the "STRATAPAX" trademark. Commercially available cutters are typically cylindrical and define planar cutting faces.
The cutting action in prior art bits is primarily performed by the outer semi-circular portion of the cutters. As the drill bit is rotated and downwardly advanced by the drill string, the cutting edges of the cutters will cut a helical groove of a generally semicircular cross-sectional configuration into the face of the formation.
Bit vibration constitutes a significant problem both to overall performance and bit wear life. The problem of vibration of a drilling bit is particularly acute when the well bore is drilled at a substantial angle to the vertical, such as in the recently popular horizontal drilling practice. In these instances, the drill bit and the adjacent drill string are subjected to the downward force of gravity and a sporadic weight on bit. These conditions produce unbalanced loading of the cutting structure, resulting in radial vibration.
Prior investigations of the effects of the vibration on a drilling bit have developed the phraseology "bit whirl" to describe this phenomena. One solution proposed by such investigations is the utilization of a low friction gauge pad on the drill bit.
One known cause of vibration is imbalanced cutting forces on the bit. Circumferential drilling imbalance forces exist to some degree on every drill bit. These imbalance forces tend to push the drill bit towards the side of the bore hole. In the example where the drill bit is provided with a normal cutting structure, the gauge cutters are designed to cut the edge of the borehole. During the cutting process, however, the effective friction between the cutters near the gauge area increases. When this occurs, the instantaneous center of rotation is translated to a point other than the geometric center or longitudinal axis of the bit. The usual result is for the drill bit to begin a reverse or backwards "whirl" around the borehole. This "whirling" process regenerates itself because insufficient friction is generated between the drill bit gauge and the borehole wall, regardless of bit orientation. This whirling also serves to change the bit center of rotation as the drill bit rotates. Thus, the cutters travel faster, in the sideways and backwards direction, and are subjected to greatly increased impact loads.
Another cause of bit vibration is from the effects of gravity. When drilling a directional hole, the drill string maintains a selected angle vis-a-vis the vertical. The drill string continues to maintain this vertical deflection even during a lateral drilling procedure. The radial forces inducing this vertical deflection can also result in bit "whirl".
Steering tools also result in bit vibration. One such cause for vibration in a steering tool occurs as a result of a bent housing. Vibration occurs when the bent housing is rotated in the bore hole resulting in off center rotation and subsequent bit whirl. Bit tilt also creates bit whirl and occurs when the drill string is not properly oriented vis-a-vis the center of the borehole. In such occasions, the end of the drill sting, and thus the drill bit, is slightly tilted.
Yet another source of bit whirl results from stratification of subsurface formations. When drilling well bores in subsurface formations it often happens that the drill bit passes readily through a comparatively soft formation and strikes a significantly harder formation. In such an instance, rarely do all of the cutters on a conventional drill bit strike this harder formation at the same time. A substantial impact force is therefore incurred by the one or two cutters that initially strike the harder formation. The end result is high impact load on the cutters of the drill bit, vibration and subsequent bit whirl.
Whatever the source of the vibration, the resulting "whirl" generates a high impact on a few of the cutters against the formation, thereby lessening drill bit life.
A number of solutions have been proposed to address the above and other disadvantages of prior art bits associated with vibration and subsequent bit "whirl". Some of these solutions have proposed the use of various geometries of the bit cutters to improve their resistance to chipping. Other proposed solutions have been directed at the use of gauge pads and protrusions placed behind the cutters.
None of these proposed solutions, however, has disclosed or suggested the use of discrete stabilizing elements whose contact face is disposed at an exaggerated angle of attack or contact vis-a-vis the formation. Quite the contrary, conventional wisdom in the drilling industry has taught that the use of exaggerated cutting angles would detrimentally impact the penetration rate of the drill bit.
Still other solutions have involved the use of shaped cutters to PDC bits to prevent bit whirl. It was traditionally believed that a shaped cutter served as a stabilizing element at any depth of cut.
Disadvantages associated with the use of traditional shaped cutters as a stabilizing element include limited wear life. In this connection, while the shaped cutter in an unsharpened condition acts as a constant stabilizing element, the nature of the cutter changes as it begins to wear. When the depth of the cut is excessive or wear removes the chamfer, the shaped cutter acts as an unchamfered cutter, and therefore loses its effectiveness as a stabilizing element in the borehole.